Various types of foulants pose problems during production and refining of hydrocarbon fluids. Foulants are materials within the production fluid that may become destabilized and agglomerate to each other and deposit on equipment, which can cause problems with the fluid during extraction, transporting, processing, refining, combustion, and the like. Examples of foulants include asphaltenes, iron sulfide, coke, ores, clays, waxes, hydrates, naphthenates, and the like.
Asphaltenes are most commonly defined as that portion of petroleum, which is insoluble in heptane. Asphaltenes exist in crude oil as both soluble species and in the form of colloidal dispersions stabilized by other components in the crude oil. Asphaltenes may include a distribution of thousands of chemical species having chemical similarities, although by no means nearly all identical. In general, asphaltenes have higher molecular weights and are the more polar fractions of crude oil, and can precipitate upon pressure, temperature, and compositional changes in crude oil resulting from blending or other mechanical or physicochemical processing. Asphaltene precipitation and deposition can cause problems in subterranean reservoirs, upstream production facilities, mid-stream transportation facilities, refineries, and fuel blending operations. In petroleum production facilities, asphaltene precipitation and deposition can occur in near-wellbore reservoir regions, wells, flowlines, separators, and other equipment. Once deposited, asphaltenes present numerous problems for crude oil producers. For example, asphaltene deposits can plug downhole tubulars, wellbores, choke off pipes and interfere with the functioning of safety shut-off valves, and separator equipment. Asphaltenes have caused problems in refinery processes such as desalters, distillation preheat units, and cokers.
Many formation fluids, such as petroleum fluids, contain a large number of components with very complex compositions. For the purposes herein, a formation fluid is the product from a crude oil well at the time the fluid is produced until it is refined. Some of the potentially fouling-causing components present in a formation fluid, for example wax and asphaltenes, are generally stable in the crude oil under equilibrium reservoir conditions, but may aggregate or deposit as temperatures, pressures, and overall fluid compositions change as the crude oil is removed from the reservoir during production. Waxes comprise predominantly high molecular weight paraffinic hydrocarbons, i.e. alkanes. Asphaltenes are typically dark brown to black-colored amorphous solids with complex structures and relatively high molecular weights.
In addition to carbon and hydrogen in the composition, asphaltenes also may contain nitrogen, oxygen and sulfur species, and may also contain metal species such as nickel, vanadium, and iron. Typical asphaltenes are known to have different solubilities in the formation fluid itself or in certain solvents like carbon disulfide or aromatic solvents, such as benzene, toluene, xylene, and the like. However, the asphaltenes are insoluble in solvents like paraffinic compounds, including but not limited to pentane, heptane, octane, etc. Asphaltene stability can even be disturbed by mixing petroleum-based fluids, such as crude oils, shale oils, condensates, and other types of formation fluids, of different origins at certain ratios as the chemistry of the petroleum-based fluids from different sources may be incompatible and induce destabilization of the foulants therein.
When the formation fluid from a subsurface formation comes into contact with a pipe, a valve, or other production equipment of a wellbore, or when there is a decrease in temperature, pressure, or change of other conditions, foulants may precipitate or separate out of a well stream or the formation fluid, while the formation fluid is flowing into and through the wellbore to the wellhead. While any foulant separation or precipitation is undesirable in and by itself, it is much worse to allow the foulant precipitants to accumulate and deposit on equipment in the wellbore. Any foulant precipitants depositing on wellbore surfaces may narrow pipes and clog wellbore perforations, various flow valves, and other wellsite and downhole locations. This may result in wellsite equipment failures and/or closure of a well. It may also slow down, reduce or even totally prevent the flow of formation fluid into the wellbore and/or out of the wellhead.
Similarly, undetected precipitations and accumulations of foulants in a pipeline for transferring crude oil could result in loss of crude oil flow and/or equipment failure. Crude oil storage facilities could have maintenance or capacity problems if foulant precipitations occur. These fluids also carry unstable foulants into the refinery, as well as possibly into finished fuels and products where the foulants cause similar problems for facilities of this nature.
Accordingly, there are large incentives to mitigate fouling during refining. There are large costs associated with shutting down production units because of the fouling components within, as well as the cost to clean the units. The foulants may create an insulating effect within the production unit, reduce the efficiency and/or reactivity, and the like. In either case, reducing the amount of fouling would reduce the cost to produce hydrocarbon fluids and the products derived therefrom.
One technique to reduce the adverse effects of foulants within the formation fluid is to add a foulant inhibitor to the petroleum-based fluid having potential fouling causing components. A ‘foulant inhibitor’ is defined herein to mean an inhibitor that targets a specific foulant. Several foulant inhibitors may be added to reduce the adverse effects of each type of foulant, e.g. asphaltene foulant inhibitors, paraffin foulant inhibitors, and iron sulfide foulant inhibitors all may be added to the fluid to decrease the adverse effects of each type of foulant, such as deposition, accumulation, and/or agglomeration of the foulant(s). However, it has been difficult to analyze the stability or efficacy of the foulant inhibitors because the experimental conditions may not always represent actual ‘field’ conditions of the formation fluid.
One such analytical technique available for measuring the stability of the foulants before and after treatment with foulant inhibitors is the ASTM D7601-04 method and minor variations thereof (hereinafter referred to as the ‘ASTM method’), and is well known by those skilled in the art. To perform this technique, a fluid sample is placed into a Turbiscan™ measurement device where the Turbiscan™ sends photons into the sample where the photons are scattered many times by objects in suspension, such as droplets, solid particles, bubbles, etc. After scattering, the photons emerge from the fluid sample and are detected by the Turbiscan™ measurement device. The Turbiscan™ measurement device utilizes a mobile reading head having a NIR diode and two detectors, which are the transmission detector and backscattering detector. No mechanical or other external stress in excess of gravitational force, i.e. equivalent to about 1×g relative centrifugal force (RCF), is added to the fluid sample. The Turbiscan™ Heavy Fuel model was specifically developed to analyze asphaltene stability in heavy fuel oil (HFO) for use with the ASTM method.
The parameters of the ASTM method using the Turbiscan™ measurement device may include a concentration of petroleum fluid that is about 1 vol % to about 10 vol %, a foulant inhibitor concentration of about 10 ppm to about 3000 ppm, and a destabilizing agent of about 90 vol % to about 99 vol %. The sample volume is 5-8 mL. The wavelength of the light is passed through the sample at 850 nm, and the pathlength of the vial is about 12 mm. The RCF is 1×g, and the temperature of the fluid during the procedure is ambient.
Another analytical technique available for measuring the stability of asphaltene foulants before and after treatment with asphaltene foulant inhibitors is the heptane precipitation test, which uses a near infrared light probe to detect the percent transmittance through the petroleum-based fluid and heptane mixture; this method is well known by those skilled in the art (hereinafter referred to as the ‘heptane precipitation method’). To perform this technique, a petroleum-based fluid(s) and the destabilizing additive (heptane) are mixed in a tube to form the fluid sample. The sample remains upright for one hour to allow asphaltene foulant molecules to flocculate and settle and/or interact with asphaltene foulant inhibitors.
The procedure may apply an optional centrifugal force to the sample after the equilibration step for a period of time. After the settling time and the optional centrifugation the percent transmittance from a light source having a wave length of 830 nm collimated light is measured with a colorimeter probe that is dipped into the upper third of the centrifugation tube. As asphaltene foulant constituents become destabilized, these molecules aggregate and settle to the bottom of the centrifugation tube. During this process, the light transmission through the sample at the upper third of the tube may increase and therefore indicate destabilization of asphaltene foulants. In addition, the volumetric amount of the precipitated asphaltenes may be quantified by visually reading the amount of solids relative to the centrifuge tube volumetric hash marks.
By calculating the % dispersive power of foulant inhibitors with the heptane precipitation method, the efficacies of different asphaltene foulant inhibitors per petroleum-based fluid may be compared. The % Dispersion afforded by an asphaltene foulant inhibitor during a heptane precipitation test having a low transmittance and high “% Dispersion” are indications of good inhibition against asphaltene foulant precipitation.
The parameters of the method using the heptane precipitation method may include a concentration of petroleum fluid that is about 1 vol % to about 10 vol %, an asphaltene foulant inhibitor concentration of about 10 ppm to about 3000 ppm, and a destabilizing additive of about 90 vol % to about 99 vol %. The sample volume is 8-12 mL. The wavelength of the light is passed through the sample at 830 nm, and the pathlength of the centrifuge vial is 20 mm.
However, there are several shortcomings when measuring foulant stability and/or efficacy of a foulant inhibitor to improve foulant stability with the Turbiscan™ or colorimeter that are discussed in more detail below. Thus, it would be desirable to develop better methods of analyzing the stability of the foulants and/or foulant inhibitors.